Placing a fluid comprising kiln dust in a wellbore through a bottom hole assembly

ABSTRACT

Embodiments relate to systems and methods for introduction of fluids comprising kiln dust into a wellbore through a bottom hole assembly. An embodiment discloses a method comprising: drilling a wellbore in a subterranean formation using a bottom hole assembly; and pumping a treatment fluid into the wellbore through the bottom hole assembly, wherein the treatment fluid comprises a kiln dust and water.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a divisional application of U.S. patent applicationSer. No. 14/091,332, filed Nov. 26, 2013, which is acontinuation-in-part of U.S. patent application Ser. No. 13/851,925,filed Mar. 27, 2013, which is a divisional application of U.S. patentapplication Ser. No. 13/725,833, filed Dec. 21, 2012, issued as U.S.Pat. No. 8,505,630 on Aug. 13, 2013, which is a continuation-in-part ofU.S. application Ser. No. 13/535,145, filed Jun. 27, 2012, issued asU.S. Pat. No. 8,505,629 on Aug. 13, 2013, which is acontinuation-in-part of U.S. application Ser. No. 12/895,436, filed Sep.30, 2010, issued as U.S. Pat. No. 8,522,872 on Sep. 3, 2013, which is acontinuation-in-part of U.S. application Ser. No. 12/264,010, filed Nov.3, 2008, issued as U.S. Pat. No. 8,333,240 on Dec. 18, 2012, which is acontinuation-in-part of U.S. application Ser. No. 11/223,669, filed Sep.9, 2005, issued as U.S. Pat. No. 7,445,669 on Nov. 4, 2008, the entiredisclosures of which are incorporated herein by reference.

BACKGROUND

Embodiments relate to subterranean operations and, in some embodiments,to introduction of fluids comprising kiln dust into a wellbore through abottom hole assembly.

Wells are generally drilled into the ground to recover natural depositsof hydrocarbons and other desirable materials trapped in geologicalformations in the Earth's crust. Wells may be drilled by rotating adrill bit which is located on a bottom hole assembly at a distal end ofa drill string. In conventional drilling, a wellbore is drilled to adesired depth and then the wellbore is lined with a larger-diameterpipe, typically referred to as a casing. Prior to inserting the casingand cementing it in place, the drill string and drill bit are removedfrom the wellbore. After the casing has been cemented in place, drillingis continued. In some instances, a technique referred to as “casingdrilling” is used in which a casing is used in place of a drillingstring. Similar to a drill string, the drill bit is connected to adistal end of the casing, and the casing is used to transmit rotationaland axial forces to the drill bit. When the wellbore has been drilled toa desired depth, the casing may be cemented in place. In some instances,cement compositions and associated spacer fluids used in the cementingoperation are placed into the wellbore through the bottom hole assembly.Casing drilling enables the well to be drilled and cased without thedelays associated with removal of the drill bit and drill string fromthe wellbore.

A number of different fluids may be used in drilling and casing thewellbore. For instance, a drilling fluid may be pumped down through thedrill string (or casing), out through the drill bit, and returned to thesurface in the annulus between the drill string and the wellbore wall.The drilling fluid can act to lubricate and cool the drill bit as wellas carry drill cuttings back to the surface. Spacer fluids can also beused in these operations. For instance, a spacer fluid may be used todisplace drilling fluids from the wellbore before introduction ofanother fluid, such as a cement composition. Cement compositions may beused to cement the casing in the wellbore. The cement composition may beallowed to set in the annulus between the casing and the wellbore wall,thereby forming an annular sheath of hardened cement (e.g., a cementsheath) that should support and position the pipe string in the wellboreand bond the exterior surface of the pipe string to the walls of thewellbore. While a variety of different fluids have been used with somesuccess in drilling and casing wellbore, improved fluids and techniquesfor their placement are needed in subterranean operations.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of some of the embodiments andshould not be used to limit or define the invention.

FIG. 1 is a schematic view of an example system that may be used forcasing while drilling in accordance with various embodiments.

FIG. 2 is a schematic view of an example system that may be used forcasing while directional drilling in accordance with variousembodiments.

FIGS. 3 and 4 are schematic views showing displacement of the drillingfluid with placement of the spacer fluid and cement composition througha bottom hole assembly in accordance with various embodiments.

FIG. 5 is a schematic view showing equipment for placement of a cementcomposition into a wellbore in accordance with various embodiments.

FIG. 6 is a graph showing measured static gel strength values at varioustemperature and pressure readings as a factor of time for an exampletreatment fluid.

FIG. 7 is a graph showing measured static gel strength values at varioustemperature and pressure readings as a factor of time for an exampletreatment fluid.

DESCRIPTION OF PREFERRED EMBODIMENTS

Embodiments relate to subterranean operations and, in some embodiments,to introduction of a treatment fluid comprising kiln dust into awellbore through a bottom hole assembly. In particular embodiments, thebottom hole assembly may be attached to a tubular, such as a drill pipeand/or a casing. By way of example, the treatment fluid may be used in acasing drilling operation, wherein the treatment fluid may be introducedinto a wellbore through a bottom hole assembly that is attached to adistal end of a casing. In some embodiments, the treatment fluid may beintroduced through a drill bit at a distal end of the bottom holeassembly. The term “treatment fluid” does not imply any particularaction by the fluid or any component thereof. Treatment fluids may beused, for example, for drilling, completion, production, work over, orin any way to prepare a wellbore and/or well equipment for recovery ofmaterials residing in a subterranean formation penetrated by thewellbore.

Referring now to FIG. 1, a casing drilling system 100 is shown inaccordance with various embodiments. As illustrated, the casing drillingsystem 100 may include a drilling platform 102 that supports a derrick104 having a traveling block 106 for raising and lowering a casing 108.The casing 108 may be generally tubular and comprise a string oftubulars, which may include conductor casing, surface casing,intermediate casing, production casing, or a production liner. Casingcollars or other suitable connectors may be used to couple joints oftubulars to form the casing 108. In some embodiments, completionequipment may be attached to the casing 108. The individual componentsof the casing 108 are not shown on FIG. 1. In the casing drillingoperation, the casing 108 is generally a larger diameter tubular thanwould typically be used for drilling. A kelly 110 may support the casing108 as it is lowered through a rotary table 112. A bottom hole assembly114 may be coupled to the distal end of the casing 108. The bottom holeassembly 114 may be a retrievable or non-retrievable bottom holeassembly. The bottom hole assembly 114 may include a drill bit 116 onits distal end and may be driven either by a downhole motor and/or viarotation of the casing 108 from the well surface. As the drill bit 116rotates, it creates a wellbore 118 that penetrates various subterraneanformations 120. In the illustrated embodiment, the bottom hole assembly114 further includes an underreamer 122, which may be used to enlargethe wellbore 118 beyond the diameter of the drill bit 116, for example.In some embodiments, the underreamer 122 may be incorporated into thedrill bit 116, incorporated with a lower end of the casing 108, or be aseparate component attached to the drill bit 116. It should be notedthat while FIG. 1 generally depicts a casing drilling system 100 beingland based, those skilled in the art will readily recognize that theprinciples described herein are equally applicable to subsea drillingoperations that employ floating or sea-based platforms and rigs, withoutdeparting from the scope of the disclosure.

A pump 124 (e.g., a mud pump) may circulate the drilling fluid 126through a feed pipe 128 and to the kelly 110, which conveys the drillingfluid 126 downhole through the interior of the casing 108 and throughone or more orifices in the drill bit 116. The drilling fluid 126 maythen be circulated back to the surface via an annulus 130 definedbetween the casing 108 and the walls of the wellbore 118. At thesurface, the recirculated or spent drilling fluid 126 exits the annulus130 and may be conveyed to one or more fluid processing unit(s) 132 viaan interconnecting flow line 134. After passing through the fluidprocessing unit(s) 132, a “cleaned” drilling fluid 126 may be depositedinto a nearby retention pit 136 (e.g., a mud pit). While illustrated asbeing arranged at the outlet of the wellbore 118 via the annulus 130,those skilled in the art will readily appreciate that the fluidprocessing unit(s) 132 may be arranged at any other location in thecasing drilling system 100 to facilitate its proper function, withoutdeparting from the scope of the scope of the disclosure.

Referring now to FIG. 2, embodiments may include directional casingdrilling. Directional drilling generally refers to the intentionaldeviation of the wellbore 118. Directional drilling may enablehorizontal drilling through one or more subterranean formations 120. Asillustrated by FIG. 2, directional casing drilling may be used to createwellbore 118 having a vertical upper section 136 and a slanted lowersection 138. Any suitable technique may be used for creation of theslanted lower section 138 that is non-vertical. In some embodiments, thebottom hole assembly 114 used in directional casing drilling may be arotatory steerable system that allows directional control whilerotating.

With reference now to FIG. 3, the drilling fluid 126 may be displacedfrom the wellbore 118 by a spacer fluid 140 in accordance with certainembodiments. In some embodiments, the spacer fluid 140 may be atreatment fluid comprising kiln dust and water. The spacer fluid 140 mayalso remove the drilling fluid, dehydrated/gelled drilling fluid, and/orfilter cake solids from the wellbore 118 in advance of the cementcomposition 142. Embodiments of the spacer fluid 140 may improve theefficiency of the removal of these and other compositions from thewellbore 118. Removal of these compositions from the wellbore 118 mayenhance bonding of the cement composition 142 to surfaces in thewellbore 118. In particular embodiments, the spacer fluid 140 comprisingkiln dust and water may be characterized by having a higher yield pointthan the drilling fluid 126 at 80° F. In further embodiments, the spacerfluid 140 comprising kiln dust and water may be characterized by havinga higher yield point than the drilling fluid 126 at 130° F. In yetfurther embodiments, the spacer fluid 140 comprising kiln dust and watermay be characterized by having a higher yield point than the drillingfluid 126 at 180° F.

The spacer fluid 140 may be pumped down through the casing 108, outthrough the bottom hole assembly 114, and into the annulus 130. In someembodiments, the spacer fluid 140 may be introduced into the annulus 130through the drill bit 116 on the bottom hole assembly 114. Asillustrated, the spacer fluid 140 may also separate the drilling fluid126 from a cement composition 142. The cement composition 142 may beintroduced into the wellbore 118 behind the spacer fluid 140 to cementthe casing 108 into the wellbore 118. The cement composition 142 mayalso be pumped down through the casing 108, out through the bottom holeassembly 114, and into the annulus 130. In some embodiments, the cementcomposition 142 may be a treatment fluid that comprises kiln dust andwater. In some embodiments, both the spacer fluid 140 and the cementcomposition 142 may comprise kiln dust. In alternative embodiments,either the spacer fluid 140 or cement composition 142 may comprise kilndust. In an additional embodiment, at least a portion of used and/orunused kiln dust containing spacer fluid 140 may be included in thecement composition 142 that is placed into the wellbore 118 and allowedto set. As will be described in more detail below the spacer fluid 140and/or cement composition 142 comprising kiln dust may also comprise oneor more additional additives in various concentrations and combinations.

Referring now to FIG. 4, the wellbore 118 is shown after displacement ofthe drilling fluid 126 in accordance with various embodiments. Asillustrated, the spacer fluid 140 and cement composition 142 may bedisposed in the annulus 130 between the casing 108 and walls of thewellbore 118. The cement composition 142 may be allowed to consolidatein the annulus 130. More particularly, the cement composition may beallowed to set in the annulus 130 to form an annular sheath of hardenedcement. The annular sheath may form a barrier that prevents themigration of fluids in the wellbore 118. The annular sheath may also,for example, support the casing 108 in the wellbore 118. In someembodiments, at least a portion of the spacer fluid 142 may also remainin the annulus 130. The remaining portion of the spacer fluid 142 mayconsolidate in the annulus 130. For example, the spacer fluid may setand harden to gain compressive strength by reaction of the kiln dust inthe water. The spacer fluid 142 after consolidation may prevent themigration of fluids in the wellbore 118 and also support the casing 108in the wellbore 118.

Referring now to FIG. 5, a cementing unit 144 is shown that may be usedin the placement of the cement composition 142 into the wellbore 118 inaccordance with certain embodiments. While not shown, the cementing unit144 may also be used in placement of the spacer fluid 140 into thewellbore 118. As will be apparent to those of ordinary skill in the art,the cementing unit 144 may include mixing equipment, such jet mixers,re-circulating mixers, or batch mixers. In some embodiments, a jet mixermay be used, for example, to continuously mix the components of thespacer fluid 140 and/or the cement composition 142 as it is being pumpedto the wellbore 118. In some embodiments, the cementing unit 144 mayinclude one or more cement trucks, which include mixing and pumpingequipment. As illustrated, the cementing unit 144 may pump the cementcomposition 142 through a feed pipe 146 and to a cementing head 148which conveys the cement composition 142 into the wellbore 118. Asfurther illustrated, fluids (e.g., the spacer fluid 140) returned to thesurface in the annulus 130 may deposited, for example, in the spacerretention pit 150 via the flow line 134.

The exemplary treatment fluids disclosed herein may directly orindirectly affect one or more components or pieces of equipmentassociated with the preparation, delivery, recapture, recycling, reuse,and/or disposal of the disclosed treatment fluids. For example, thedisclosed treatment fluids may directly or indirectly affect one or moremixers, related mixing equipment, mud pits (e.g., retention pit 136,spacer retention pit 150), storage facilities or units, compositionseparators, heat exchangers, sensors, gauges, pumps, compressors, andthe like used generate, store, monitor, regulate, and/or recondition theexemplary treatment fluids. The disclosed treatment fluids may alsodirectly or indirectly affect any transport or delivery equipment usedto convey the treatment fluids to a well site or downhole such as, forexample, any transport vessels, conduits, pipelines, trucks, tubulars,and/or pipes used to compositionally move the treatment fluids from onelocation to another, any pumps, compressors, or motors (e.g., topside ordownhole) used to drive the treatment fluids into motion, any valves orrelated joints used to regulate the pressure or flow rate of thetreatment fluids, and any sensors (i.e., pressure and temperature),gauges, and/or combinations thereof, and the like. The disclosedtreatment fluids may also directly or indirectly affect the variousdownhole equipment and tools that may come into contact with thetreatment fluids such as, but not limited to, wellbore casing (e.g.,casing 108), wellbore liner, completion string, insert strings, drillstring, coiled tubing, slickline, wireline, drill pipe, drill collars,mud motors, downhole motors and/or pumps, cement pumps, surface-mountedmotors and/or pumps, centralizers, turbolizers, scratchers, floats(e.g., shoes, collars, valves, etc.), logging tools and relatedtelemetry equipment, actuators (e.g., electromechanical devices,hydromechanical devices, etc.), sliding sleeves, production sleeves,plugs, screens, filters, flow control devices (e.g., inflow controldevices, autonomous inflow control devices, outflow control devices,etc.), couplings (e.g., electro-hydraulic wet connect, dry connect,inductive coupler, etc.), control lines (e.g., electrical, fiber optic,hydraulic, etc.), surveillance lines, drill bits (e.g., drill bit 116)and reamers, sensors or distributed sensors, downhole heat exchangers,valves and corresponding actuation devices, tool seals, packers, cementplugs, bridge plugs, and other wellbore isolation devices, orcomponents, and the like.

Embodiments of the treatment fluids (e.g., spacer fluid 140, cementcomposition 142) may comprise kiln dust and water. In some embodiments,the treatment fluids may consolidate when left in a wellbore. Forexample, the treatment fluids may set and harden to gain compressivestrength by reaction of the kiln dust in the water. In some embodiments,the treatment fluids may be foamed. For example, the foamed treatmentfluids may comprise water, kiln dust, a foaming agent, and a gas. Afoamed treatment fluid may be used, for example, where it is desired forthe fluid to be lightweight and not exert excessive force onsubterranean formations 120 penetrated by the wellbore 118. Embodimentsof the treatment fluids may further comprise fly ash, barite, pumicite,a free water control additive, or a combination thereof. In accordancewith present embodiments, the treatment fluid may be a spacer fluid 140that displaces a first fluid (e.g., a drilling fluid 126) from thewellbore 118. In some embodiments, the spacer fluid 140 may have ahigher yield point than the first fluid. In further embodiments, thetreatment fluid may be a cement composition 142 that is used incementing the casing 108 in the wellbore 118. Embodiment may furthercomprise using a treatment fluid comprising the kiln dust in drillingthe wellbore 118. For example, the treatment fluid may be circulatedpast the drill bit 116 to carry drill cuttings back to the surface.

The treatment fluids generally should have a density suitable for aparticular application as desired by those of ordinary skill in the art,with the benefit of this disclosure. In some embodiments, the treatmentfluids may have a density in the range of from about 4 pounds per gallon(“ppg”) to about 24 ppg. In other embodiments, the treatment fluids mayhave a density in the range of about 4 ppg to about 17 ppg. In yet otherembodiments, the treatment fluids may have a density in the range ofabout 8 ppg to about 13 ppg. Embodiments of the treatment fluids may befoamed or unfoamed or comprise other means to reduce their densitiesknown in the art, such as lightweight additives. Those of ordinary skillin the art, with the benefit of this disclosure, should recognize theappropriate density for a particular application.

Kiln dust, as that term is used herein, refers to a solid materialgenerated as a by-product of the heating of certain materials in kilns.The term “kiln dust” as used herein is intended to include kiln dustmade as described herein and equivalent forms of kiln dust. Kiln dusttypically exhibits cementitious properties in that it can set and hardenin the presence of water. Examples of suitable kiln dusts include cementkiln dust, lime kiln dust, and combinations thereof. Cement kiln dustmay be generated as a by-product of cement production that is removedfrom the gas stream and collected, for example, in a dust collector.Usually, large quantities of cement kiln dust are collected in theproduction of cement that are commonly disposed of as waste. Disposal ofthe cement kiln dust can add undesirable costs to the manufacture of thecement, as well as the environmental concerns associated with itsdisposal. The chemical analysis of the cement kiln dust from variouscement manufactures varies depending on a number of factors, includingthe particular kiln feed, the efficiencies of the cement productionoperation, and the associated dust collection systems. Cement kin dustgenerally may comprise a variety of oxides, such as SiO₂, Al₂O₃, Fe₂O₃,CaO, MgO, SO₃, Na₂O, and K₂O. Problems may also be associated with thedisposal of lime kiln dust, which may be generated as a by-product ofthe calcination of lime. The chemical analysis of lime kiln dust fromvarious lime manufacturers varies depending on a number of factors,including the particular limestone or dolomitic limestone feed, the typeof kiln, the mode of operation of the kiln, the efficiencies of the limeproduction operation, and the associated dust collection systems. Limekiln dust generally may comprise varying amounts of free lime and freemagnesium, lime stone, and/or dolomitic limestone and a variety ofoxides, such as SiO₂, Al₂O₃, Fe₂O₃, CaO, MgO, SO₃, Na₂O, and K₂O, andother components, such as chlorides.

The kiln dust may be included in embodiments of the treatment fluids asa rheology modifier. Among other things, using the kiln dust in variousembodiments can provide treatment fluids having rheology suitable for aparticular application. Desirable rheology may be advantageous toprovide a treatment fluid that is effective for drilling fluiddisplacement, for example, in spacer fluid embodiments. In someinstances, the kiln dust can be used to provide a treatment fluid with alow degree of thermal thinning. For example, the treatment fluid mayeven have a yield point that increases at elevated temperatures, such asthose encountered downhole.

The kiln dust may be included in the spacer fluids in an amountsufficient to provide, for example, the desired rheological properties.The concentration of kiln dust may also be selected to provide a lowcost replacement for higher cost additives, such as Portland cement,that may typically be included in a particular treatment fluid. In someembodiments, the kiln dust may be present in a treatment fluid in anamount in the range of from about 1% to about 65% by weight of thetreatment fluid (e.g., about 1%, about 5%, about 10%, about 15%, about20%, about 25%, about 30%, about 35%, about 40%, about 45%, about 50%,about 55%, about 60%, about 65%, etc.). In some embodiments, the kilndust may be present in the treatment fluid in an amount in the range offrom about 5% to about 60% by weight of the treatment fluid. In someembodiments, the kiln dust may be present in an amount in the range offrom about 20% to about 35% by weight of the treatment fluid.Alternatively, the amount of kiln dust may be expressed by weight ofcementitious components (“bwocc”). As used herein, the term “by weightof cementitious components” or “bwocc” refers to the amount of acomponent, such as kiln dust, relative to the overall amount ofcementitious components used in preparation of the treatment fluid.Cementitious components include those components or combinations ofcomponents of the treatment fluid that set, or otherwise harden, todevelop compressive strength, including, for example, kiln dust,hydraulic cement, fly ash, hydrated lime, and the like. For example, thekiln dust may be present in an amount in a range of from about 1% to100% bwocc. (e.g., about 1%, about 5%, about 10%, about 20%, about 30%,about 40%, about 50%, about 60%, about 70%, about 80%, about 90%, 100%,etc.). In some embodiments, the kiln dust may be present in an amount inthe range of from about 50% to 100% and, alternatively, from about 80%to 100% bwocc. One of ordinary skill in the art, with the benefit ofthis disclosure, should recognize the appropriate amount of kiln dust toinclude for a chosen application.

The water used in an embodiment of the treatment fluids may include, forexample, freshwater, saltwater (e.g., water containing one or more saltsdissolved therein), brine (e.g., saturated saltwater produced from asubterranean formations), seawater, or any combination thereof.Generally, the water may be from any source, provided that the waterdoes not contain an excess of compounds that may undesirably affectother components in the treatment fluid. The water may be included in anamount sufficient to form a pumpable fluid. In some embodiments, thewater may be included in the treatment fluids in an amount in a range offrom about 40% to about 200% bwocc. In some embodiments, the water maybe included in an amount in a range of from about 40% to about 150%bwocc.

Optionally, embodiments of the treatment fluids may further comprise flyash. A variety of fly ashes may be suitable, including fly ashclassified as Class C or Class F fly ash according to American PetroleumInstitute, API Specification for Materials and Testing for Well Cements,API Specification 10, Fifth Ed., Jul. 1, 1990. Suitable examples of flyash include, but are not limited to, POZMIX® A cement additive,commercially available from Halliburton Energy Services, Inc., Duncan,Okla. Where used, the fly ash generally may be included in the treatmentfluids in an amount desired for a particular application. In someembodiments, the fly ash may be present in an amount in a range of fromabout 1% to about 99% bwocc (e.g., about 1%, about 5%, about 10%, about20%, about 30%, about 40%, about 50%, about 60%, about 70%, about 80%,about 90%, about 99%, etc.). In some embodiments, the fly ash may bepresent in an amount in the range of from about 1% to about 20% and,alternatively, from about 1% to about 10% bwocc. One of ordinary skillin the art, with the benefit of this disclosure, should recognize theappropriate amount of the fly ash to include for a chosen application.

Optionally, embodiments of the treatment fluids may further comprisebarite. In some embodiments, the barite may be sized barite. Sizedbarite generally refers to barite that has been separated, sieved,ground, or otherwise sized to produce barite having a desired particlesize. For example, the barite may be sized to produce barite having aparticle size less than about 200 microns in size. Where used, thebarite generally may be included in the treatment fluids in an amountdesired for a particular application. For example, the barite may bepresent in an amount in a range of from about 1% to about 99% bwocc(e.g., about 1%, about 5%, about 10%, about 20%, about 30%, about 40%,about 50%, about 60%, about 70%, about 80%, about 90%, about 99%, etc.).In some embodiments, the barite may be present in an amount in the rangeof from about 1% to about 20% and, alternatively, from about 1% to about10% bwocc. One of ordinary skill in the art, with the benefit of thisdisclosure, should recognize the appropriate amount of the barite toinclude for a chosen application.

Optionally, embodiments of the treatment fluids may further comprisepumicite. Generally, pumicite is a volcanic rock that may exhibitscementitious properties, in that it may set and harden in the presenceof hydrated lime and water. Hydrated lime may be used in combinationwith the pumicite, in some embodiments. Where used, the pumicitegenerally may be included in the treatment fluids in an amount desiredfor a particular application. For example, the pumicite may be presentin an amount in a range of from about 1% to about 99% bwocc (e.g., about1%, about 5%, about 10%, about 20%, about 30%, about 40%, about 50%,about 60%, about 70%, about 80%, about 90%, about 99%, etc.). In someembodiments, the pumicite may be present in an amount in the range offrom about 1% to about 20% and, alternatively, from about 1% to about10% bwocc. One of ordinary skill in the art, with the benefit of thisdisclosure, should recognize the appropriate amount of the pumicite toinclude for a chosen application.

Optionally, embodiments of the treatment fluids may further comprise afree water control additive. As used herein, the term “free watercontrol additive” refers to an additive included in a liquid for, amongother things, reducing (or preventing) the presence of free water in theliquid. Free water control additives may also reduce (or prevent) thesettling of solids. Examples of suitable free water control additivesinclude, but are not limited to, bentonite, amorphous silica,hydroxyethyl cellulose, and combinations thereof. An example of asuitable free water control additive is SA-1015™ suspending agent,available from Halliburton Energy Services, Inc. Another example of asuitable free water control additive is WG-17™ solid additive, availablefrom Halliburton Energy Services, Inc. The free water control additivemay be provided as a dry solid in some embodiments. Where used, the freewater control additive may be present in an amount in the range of fromabout 0.1% to about 16% bwocc, for example. In alternative embodiments,the free water control additive may be present in an amount in the rangeof from about 0.1% to about 2% bwocc.

In some embodiments, the treatment fluids may further comprise alightweight additive. The lightweight additive may be included to reducethe density of embodiments of the treatment fluids. For example, thelightweight additive may be used to foam a treatment fluid, for example,having a density of less than about 13 ppg. The lightweight additivetypically may have a specific gravity of less than about 2.0. Examplesof suitable lightweight additives may include sodium silicate, hollowmicrospheres, gilsonite, perlite, and combinations thereof. An exampleof a suitable sodium silicate is ECONOLITE™ additive, available fromHalliburton Energy Services, Inc. Where used, the lightweight additivemay be present in an amount in the range of from about 0.1% to about 20%bwocc, for example. In alternative embodiments, the lightweight additivemay be present in an amount in the range of from about 1% to about 10%bwocc.

As previously mentioned, embodiments of the treatment fluids may befoamed with a gas, for example, to provide a treatment fluid with areduced density. It should be understood that reduced densities may beneeded in displacement embodiments to more approximately match thedensity of a particular drilling fluid, for example, where lightweightdrilling fluids are being used. The drilling fluid 126 may be consideredlightweight if it has a density of less than about 13 ppg,alternatively, less than about 10 ppg, and alternatively less than about9 ppg. In some embodiments, the treatment fluids may be foamed to have adensity within about 10% of the density of the drilling fluid 126 and,alternatively, within about 5% of the density of the drilling fluid 126.While techniques, such as lightweight additives, may be used to reducethe density of the treatment fluids comprising kiln dust withoutfoaming, these techniques may have drawbacks. For example, reduction ofthe treatment fluid's density to below about 13 ppg using lightweightadditives may produce unstable slurries, which can have problems withsettling of solids, floating of lightweight additives, and free water,among others. Accordingly, the treatment fluid may be foamed to providea treatment fluid having a reduced density that is more stable.

Therefore, in some embodiments, the treatment fluids may be foamed andcomprise water, kiln dust, a foaming agent, and a gas. Optionally, toprovide a treatment fluid with a lower density and more stable foam, thetreatment fluid may further comprise a lightweight additive, forexample. With the lightweight additive, a base slurry may be preparedthat may then be foamed to provide an even lower density. In someembodiments, the foamed treatment fluid may have a density in the rangeof from about 4 ppg to about 13 ppg and, alternatively, about 7 ppg toabout 9 ppg. In one particular embodiment, a base slurry may be foamedfrom a density of in the range of from about 9 ppg to about 13 ppg to alower density, for example, in a range of from about 7 ppg to about 9ppg.

The gas used in embodiments of the foamed treatment fluids may be anysuitable gas for foaming the treatment fluid, including, but not limitedto air, nitrogen, and combinations thereof. Generally, the gas should bepresent in embodiments of the foamed treatment fluids in an amountsufficient to form the desired foam. In certain embodiments, the gas maybe present in an amount in the range of from about 5% to about 80% byvolume of the foamed treatment fluid at atmospheric pressure,alternatively, about 5% to about 55% by volume, and, alternatively,about 15% to about 30% by volume.

Where foamed, embodiments of the treatment fluids may comprise a foamingagent for providing a suitable foam. As used herein, the term “foamingagent” refers to a material (e.g., surfactant) or combination ofmaterials that facilitate the formation of a foam in a liquid, forexample, by reduction of surface tension. Any suitable foaming agent forforming a foam in an aqueous liquid may be used in embodiments of thetreatment fluids. Examples of suitable foaming agents may include, butare not limited to: mixtures of an ammonium salt of an alkyl ethersulfate, a cocoamidopropyl betaine surfactant, a cocoamidopropyldimethylamine oxide surfactant, sodium chloride, and water; mixtures ofan ammonium salt of an alkyl ether sulfate surfactant, a cocoamidopropylhydroxysultaine surfactant, a cocoamidopropyl dimethylamine oxidesurfactant, sodium chloride, and water; hydrolyzed keratin; mixtures ofan ethoxylated alcohol ether sulfate surfactant, an alkyl or alkeneamidopropyl betaine surfactant, and an alkyl or alkene dimethylamineoxide surfactant; aqueous solutions of an alpha-olefinic sulfonatesurfactant and a betaine surfactant; and combinations thereof. Anexample of a suitable foaming agent is FOAMER™ 760 foamer/stabilizer,available from Halliburton Energy Services, Inc. Generally, the foamingagent may be present in embodiments of the foamed treatment fluids in anamount sufficient to provide a suitable foam. In some embodiments, thefoaming agent may be present in an amount in the range of from about0.8% to about 5% by volume of the water (“bvow”).

A wide variety of additional additives may be included in the treatmentfluids as deemed appropriate by one skilled in the art, with the benefitof this disclosure. Examples of such additives include, but are notlimited to: supplementary cementitious materials, weighting agents,viscosifying agents (e.g., clays, hydratable polymers, guar gum), fluidloss control additives, lost circulation materials, filtration controladditives, dispersants, defoamers, corrosion inhibitors, scaleinhibitors, formation conditioning agents, and water-wetting surfactant.Water-wetting surfactants may be used to aid in removal of oil fromsurfaces in the wellbore (e.g., the casing) to enhance cement andconsolidating spacer fluid bonding. Examples of suitable weightingagents include, for example, materials having a specific gravity of 3 orgreater, such as barite. Specific examples of these, and other,additives include: organic polymers, biopolymers, latex, ground rubber,surfactants, crystalline silica, amorphous silica, silica flour, fumedsilica, nano-clays (e.g., clays having at least one dimension less than100 nm), salts, fibers, hydratable clays, microspheres, rice husk ash,micro-fine cement (e.g., cement having an average particle size of fromabout 5 microns to about 10 microns), metakaolin, zeolite, shale,Portland cement, Portland cement interground with pumice, perlite,barite, slag, lime (e.g., hydrated lime), gypsum, and any combinationsthereof, and the like. In some embodiments, a supplementary cementitiousmaterial may be included in the treatment fluid in addition to or inplace of all or a portion of the kiln dust. Examples of suitablesupplementary cementitious materials include, without limitation,Portland cement, Portland cement interground with pumice, micro-finecement, fly ash, slag, pumicite, gypsum and any combination thereof. Aperson having ordinary skill in the art, with the benefit of thisdisclosure, will readily be able to detelinine the type and amount ofadditive useful for a particular application and desired result. Itshould be understood that, while the present disclosure describes anumber of optional additives that may be included in the treatmentfluids, it is intended to cover all combinations of the disclosedadditives.

As previously mentioned, embodiments of the treatment fluids (e.g.,cement composition 142, spacer fluid 140, etc.) may be consolidating inthat the treatment fluids may develop gel strength and/or compressivestrength in the wellbore 118. Consolidation is defined herein as one ofthree types of material behavior: Type 1 consolidation is identifiableas a gelled fluid that can be moved and/or pumped when the hydraulicshear stress exceeds the yield point (YP) of the gel. Type 2consolidation is identifiable as a plastic semi-solid that canexperience “plastic deformation” if the shear stress, compressivestress, or tensile stress exceeds the “plastic yield limit.” Type 3consolidation is identifiable as a rigid solid similar to regular setcement. During a steady progressive strain rate during conventionalcompressive testing, both confined and unconfined, a Type 3 consolidatedmaterial would exhibit linear elastic Hookean stress-strain behavior,followed by some plastic yield and/or mechanical failure. The treatmentfluid may transform from the pumpable fluid that was placed during thenormal displacement operation to Type 1 and/or further progress to Type2 and/or further progress to Type 3. It should be understood that theconsolidation of the treatment fluid is at wellbore conditions and, aswill be appreciated by those of ordinary skill in the art, wellboreconditions may vary. However, embodiments of the treatment fluids may becharacterized by exhibiting Type 1, Type 2, or Type 3 consolidationunder specific wellbore conditions.

Specific examples of how to characterize a Type 1 consolidation includemeasuring the yield stress. Type 1 consolidation exhibits a YP fromabout 25 Pascals to about 250 Pascals, where YP is measured by one ofthe methods described in U.S. Pat. No. 6,874,353, namely: using a seriesof parallel vertical blades on a rotor shaft, referred to by thoseskilled in the art as the “Vane Method”; or using the new device andmethod also described in U.S. Pat. No. 6,874,353. Another method used todefine the YP of Type 1 consolidation is defined in Morgan, R. G.,Suter, D. A., and Sweat, V. A., Mathematical Analysis of a Simple BackExtrusion Rheometer, ASAE Paper No. 79-6001. Additionally, other methodscommonly known to those skilled in the art may be used to define the YPof Type 1 consolidated treatment fluid. Alternatively, another method ofcharacterizing a Type 1 consolidation includes measuring the gelledstrength of the material, which may be defined as “Static Gel Strength”(SGS) as is defined and measured in accordance with the API RecommendedPractice on Determining the Static Gel Strength of Cement Formations,ANSI/API Recommended Practice 10B-6. A Type 1 consolidation may exhibitSGS values from about 70 lbf/100 ft² up to about 500 lbf/100 ft².

Specific examples of how to characterize a Type 2 consolidation includemeasuring the yield limit in compression (YL-C). The YL-C refers to theuniaxial compressive stress at which the material experiences apermanent deformation. Permanent deformation refers to a measurabledeformation strain that does not return to zero over a period of timethat is on the same order of magnitude as the total time required toconduct the measurement. YL-C may range from 1 psi (lbf/in²) to 2,000psi, with the most common values ranging from 5 psi to 500 psi.

Specific examples of how to characterize a Type 3 consolidation includemeasuring the compressive strength. Type 3 consolidation will exhibitunconfined uniaxial compressive strengths ranging from about 5 psi toabout 10,000 psi, while the most common values will range from about 10psi to about 2,500 psi. These values are achieved in 7 days or less.Some formulations may be designed so as to provide significantcompressive strengths within 24 hours to 48 hours. Typical samplegeometry and sizes for measurement are similar to, but not limited to,those used for characterizing oil well cements: 2 inch cubes; or 2 inchdiameter cylinders that are 4 inches in length; or 1 inch diametercylinders that are 2 inches in length; and other methods known to thoseskilled in the art of measuring “mechanical properties” of oil wellcements. For example, the compressive strength may be determined bycrushing the samples in a compression-testing machine. The compressivestrength is calculated from the failure load divided by thecross-sectional area resisting the load and is reported in units ofpound-force per square inch (psi). Compressive strengths may bedetermined in accordance with API RP 10B-2, Recommended Practice forTesting Well Cements, First Edition, July 2005.

As a specific example of consolidation, when left in an annulus 130(e.g., between walls of the wellbore 118 and the casing 108 or betweenthe casing 108 and a larger conduit disposed in the wellbore 118), thetreatment fluid may consolidate to develop static gel strength and/orcompressive strength. The consolidated mass formed in the annulus 130may act to support and position the casing 108 in the wellbore 118 andbond the exterior surface of the casing 108 to the walls of the wellbore118 or to the larger conduit. The consolidated mass formed in theannulus 130 may also provide a substantially impermeable barrier to sealoff formation fluids and gases and consequently also serve to mitigatepotential fluid migration. The consolidated mass formed in the annulus130 may also protect the casing 108 or other conduit from corrosion.

In some embodiments, consolidation of the treatment fluid (e.g., spacerfluid 140 or cement composition 142) in the wellbore 118 may bemeasured. The consolidation measurement may also include a measurementof the integrity of the bond formed between the consolidated treatmentfluid and the exterior wall of the casing 108 and/or between theconsolidated fluid and the walls of the wellbore 118 or larger conduitdisposed in the wellbore 118. In some embodiments, data may be collectedcorresponding to the integrity of this bond, and the data may berecorded on a log, commonly referred to as a “bond long.” The bond logmay be used to, for example, analyze the consolidation properties of thetreatment fluid in the wellbore 118. Accordingly, embodiments mayinclude running a cement bond log on at least the portion of thewellbore 118 containing the consolidated treatment fluid. The cementbond log for the consolidated treatment fluid may be obtained by anymethod used to measure cement integrity without limitation. In someembodiments, a tool may be run into the wellbore 118 on a wireline thatcan detect the bond of the consolidated treatment fluid to the casing108 and/or the walls of the wellbore 118 (or larger conduit). An exampleof a suitable tool includes a sonic tool.

Embodiments of the treatments fluids (e.g., spacer fluid 140) may have atransition time that is shorter than the transition time of anotherfluid (e.g., cement composition 142) subsequently introduced into thewellbore 118. The term “transition time,” as used herein, refers to thetime for a fluid to progress from a static gel strength of about 100lbf/100 ft² to about 500 lbf/100 ft². By having a shorter transitiontime, the treatment fluid can reduce or even prevent migration of gas inthe wellbore 118, even if gas migrates through a subsequently introducedcement composition 124 before it has developed sufficient gel strengthto prevent such migration. Gas and liquid migration can typically beprevented at a static gel strength of 500 lbf/100 ft². By reducing theamount of gas that can migrate through the wellbore 118, thesubsequently added cement composition 142 can progress through itsslower transition period without gas migration being as significantfactor as the cement develops static gel strength. Some embodiments ofthe treatment fluids may have a transition time (i.e., the time toprogress from a static gel strength of about 100 lbf/100 ft² to about500 lbf/100 ft²) at wellbore conditions of about 45 minutes or less,about 30 minutes or less, about 20 minutes or less, or about 10 minutesor less. Embodiments of the treatment fluids also quickly develop staticgel strengths of about 100 lbf/100 ft² and about 500 lbf/100 ft²,respectively, at wellbore conditions. The time for a fluid to a developa static gel strength of about 100 lbf/100 ft² is also referred to asthe “zero gel time.” For example, the treatment fluids may have a zerogel time at wellbore condition of about 8 hours or less, and,alternatively, about 4 hours or less. In some embodiments, the treatmentfluids may have a zero gel time in a range of from about 0 minutes toabout 4 hours or longer. By way of further example, the treatment fluidsmay develop static gel strengths of about 500 lbf/100 ft² or more atwellbore conditions in a time of from about 10 minutes to about 8 hoursor longer. The preceding time for development of static gel strengthsare listed as being at wellbore conditions. Those of ordinary skill inthe art will understand that particular wellbore conditions (e.g.,temperature, pressure, depth, etc.) will vary; however, embodiments ofthe treatment fluids should meet these specific requirements at thewellbore conditions. Static gel strength may be measured in accordancewith API Recommended Practice on Determining the Static Gel Strength ofCement Formations, ANSI/API Recommended Practice 10B-6.

Embodiments of the treatment fluids may be prepared in accordance withany suitable technique. In some embodiments, the desired quantity ofwater may be introduced into a mixer (e.g., a cement blender) followedby the dry blend. The dry blend may comprise the kiln dust andadditional solid additives, for example. Additional liquid additives, ifany, may be added to the water as desired prior to, or after,combination with the dry blend. This mixture may be agitated for asufficient period of time to form a base slurry. This base slurry maythen be introduced into the wellbore 118 via pumps (e.g., cementing unit144), for example. In the foamed embodiments, the base slurry may bepumped into the wellbore 118, and a foaming agent may be metered intothe base slurry followed by injection of a gas, e.g., at a foam mixing“T,” in an amount sufficient to foam the base slurry thereby forming afoamed treatment fluid, in accordance with certain embodiments. Afterfoaming, the foamed treatment fluid may be introduced into the wellbore118. As will be appreciated by those of ordinary skill in the art, withthe benefit of this disclosure, other suitable techniques for preparingtreatment fluids may be used in accordance with the present disclosure.

In some embodiments, methods may include enhancing rheologicalproperties of a treatment fluid (e.g., spacer fluid 140, cementcomposition 142, etc.). The method may comprise including kiln dust in atreatment fluid. Optional additives as described previously may also beincluded in the treatment fluid. The kiln dust may be included in thetreatment fluid in an amount sufficient to provide a higher yield pointthan a first fluid. The higher yield point may be desirable, forexample, to effectively displace the first fluid from the wellbore. Asused herein, the term “yield point” refers to the resistance of a fluidto initial flow, or representing the stress required to start fluidmovement. In an embodiment, the yield point of the treatment fluid at atemperature of up to about 180° F. is greater than about 5 lb/100 ft².In an embodiment, the yield point of the treatment fluid at atemperature of up to about 180° F. is greater than about 10 lb/100 ft².In an embodiment, the yield point of the treatment fluid at atemperature of up to about 180° F. is greater than about 20 lb/100 ft².It may be desirable for the treatment fluid to not thermally thin to ayield point below the first fluid at elevated temperatures. Accordingly,the treatment fluid may have a higher yield point than the first fluidat elevated temperatures, such as 180° F. or bottom hole statictemperature (“BHST”). In one embodiment, the treatment fluid may have ayield point that increases at elevated temperatures. For example, thetreatment fluid may have a yield point that is higher at 180° F. than at80° F. By way of further example. The treatment fluid may have a yieldpoint that is higher at BHST than at 80° F.

In some embodiments, the treatment fluids may be used in thedisplacement of a drilling fluid 126 from a wellbore 118. The drillingfluid 126 may include, for example, any number of fluids, such as solidsuspensions, mixtures, and emulsions. In some embodiments, the drillingfluid 126 may comprise an oil-based drilling fluid. An example of asuitable oil-based drilling fluid comprises an invert emulsion. In someembodiments, the oil-based drilling fluid may comprise an oleaginousfluid. Examples of suitable oleaginous fluids that may be included inthe oil-based drilling fluids include, but are not limited to,α-olefins, internal olefins, alkanes, aromatic solvents, cycloalkanes,liquefied petroleum gas, kerosene, diesel oils, crude oils, gas oils,fuel oils, paraffin oils, mineral oils, low-toxicity mineral oils,olefins, esters, amides, synthetic oils (e.g., polyolefins),polydiorganosiloxanes, siloxanes, organosiloxanes, ethers, acetals,dialkylcarbonates, hydrocarbons, and combinations thereof.

To facilitate a better understanding of the present invention, thefollowing examples of certain aspects of some embodiments are given. Inno way should the following examples be read to limit, or define, thescope of the invention. In the following examples, concentrations aregiven in weight percent of the overall composition.

Example 1

Sample treatment fluids were prepared to evaluate the rheologicalproperties of spacer fluids containing kiln dust. In this example,cement kiln dust was used. The sample treatment fluids were prepared asfollows. First, all dry components (e.g., cement kiln dust, fly ash,bentonite, free water control additive, etc.) were weighed into a glasscontainer having a clean lid and agitated by hand until blended. Tapwater was then weighed into a Waring blender jar. The dry componentswere then mixed into the water with 4,000 rpm stirring. The blenderspeed was then increased to 12,000 rpm for about 35 seconds.

Sample Spacer Fluid No. 1 was an 11 pound per gallon slurry thatcomprised 60.62% water, 34.17% cement kiln dust, 4.63% fly ash, and0.58% free water control additive (WG-17™ solid additive).

Sample Spacer Fluid No. 2 was an 11 pound per gallon slurry thatcomprised 60.79% water, 30.42% cement kiln dust, 4.13% fly ash, 0.17%free water control additive (WG-17™ solid additive), 3.45% bentonite,and 1.04% Econolite™ additive.

Rheological values were then determined using a Fann Model 35Viscometer. Dial readings were recorded at speeds of 3, 6, 100, 200, and300 with a B1 bob, an R1 rotor, and a 1.0 spring. The dial readings,plastic viscosity, and yield points for the spacer fluids were measuredin accordance with API Recommended Practices 10B, Bingham plastic modeland are set forth in the table below. The abbreviation “PV” refers toplastic viscosity, while the abbreviation “YP” refers to yield point.

TABLE 1 YP (lb/ Sample Temp. Viscometer RPM PV 100 Fluid (° F.) 300 200100 6 3 (cP) ft²) 1 80 145 127 90 24 14 113.3 27.4 180 168 143 105 26 15154.5 30.3 2 80 65 53 43 27 22 41.1 26.9 180 70 61 55 22 18 51.6 25.8

The thickening time of the Sample Fluid No. 1 was also determined inaccordance with API Recommended Practice 10B at 205° F. Sample Fluid No.1 had a thickening time of more than 6:00+ hours.

Accordingly, the above example illustrates that the addition of cementkiln dust to a treatment fluid may provide suitable properties for usein subterranean applications. In particular, the above exampleillustrates, inter alia, that the cement kiln dust may be used toprovide a treatment fluid that may not exhibit thermal thinning with thetreatment fluid potentially even having a yield point that increaseswith temperature. For example, Sample Fluid No. 2 had a higher yieldpoint at 180° F. than at 80° F. In addition, the yield point of SampleFluid No. 1 had only a slight decrease at 180° F. as compared to 80° F.Even further, the example illustrates that addition of the cement kilndust to a treatment fluid may provide a plastic viscosity that increaseswith temperature.

Example 2

Additional sample treatment fluids were prepared to further evaluate therheological properties of spacer fluids containing kiln dust. Cementkiln dust was used in this example, The sample treatment fluids wereprepared as follows. First, all dry components (e.g., cement kiln dust,fly ash) were weighed into a glass container having a clean lid andagitated by hand until blended. Tap water was then weighed into a Waringblender jar. The dry components were then mixed into the water with4,000 rpm stirring. The blender speed was then increased to 12,000 rpmfor about 35 seconds.

Sample Fluid No. 3 was a 12.5 pound per gallon fluid that comprised47.29% water and 52.71% cement kiln dust.

Sample Fluid No. 4 was a 12.5 pound per gallon fluid that comprised46.47% water, 40.15% cement kiln dust, and 13.38% fly ash.

Sample Fluid No. 5 was a 12.5 pound per gallon fluid that comprised45.62% water, 27.19% cement kiln dust, and 27.19% fly ash.

Sample Fluid No. 6 was a 12.5 pound per gallon fluid that comprised44.75% water, 13.81% cement kiln dust, and 41.44% fly ash.

Sample Fluid No. 7 (comparative) was a 12.5 pound per gallon fluid thatcomprised 43.85% water, and 56.15% fly ash.

Rheological values were then determined using a Fann Model 35Viscometer. Dial readings were recorded at speeds of 3, 6, 30, 60, 100,200, 300, and 600 with a B1 bob, an R1 rotor, and a 1.0 spring. The dialreadings, plastic viscosity, and yield points for the spacer fluids weremeasured in accordance with API Recommended Practices 10B, Binghamplastic model and are set forth in the table below. The abbreviation“PV” refers to plastic viscosity, while the abbreviation “YP” refers toyield point.

TABLE 2 Cement Kiln YP Dust- (lb/ Sample Fly Ash Temp. Viscometer RPM PV100 Fluid Ratio (° F.) 600 300 200 100 60 30 6 3 (cP) ft²) 3 100:0  8033 23 20 15 13 12 8 6 12 11 130 39 31 27 23 22 19 16 11 12 19 180 66 5851 47 40 38 21 18 16.5 41.5 4 75:25 80 28 22 19 15 14 11 8 6 10.5 11.5130 39 28 25 21 19 16 14 11 10.5 17.5 180 51 39 36 35 31 26 16 11 6 33 550:50 80 20 11 8 6 5 4 4 3 7.5 3.5 130 21 15 13 10 9 8 6 5 7.5 7.5 18025 20 17 14 13 12 7 5 9 11 6 25:75 80 16 8 6 3 2 1 0 0 7.5 0.5 130 15 86 4 3 2 1 1 6 2 180 15 9 7 5 4 4 2 2 6 3 7  0:100 80 16 7 5 3 1 0 0 0 61 (Comp.) 130 11 4 3 1 0 0 0 0 4.5 −0.5 180 8 3 2 0 0 0 0 0 4.5 −1.5

Accordingly, the above example illustrates that the addition of thecement kiln dust to a treatment fluid may provide suitable propertiesfor use in subterranean applications. In particular, the above exampleillustrates, inter alia, that the cement kiln dust may be used toprovide a treatment fluid that may not exhibit thermal thinning with thetreatment fluid potentially even having a yield point that increaseswith temperature. In addition, as illustrated in Table 2 above, higheryield points were observed for treatment fluids with higherconcentrations of the cement kiln dust.

Example 3

A sample treatment fluid containing kiln dust was prepared to comparethe rheological properties of a treatment fluid containing kiln dustwith an oil-based drilling fluid. In this example, cement kiln dust wasused. The sample fluid was prepared as follows. First, all drycomponents (e.g., cement kiln dust, fly ash, bentonite, etc.) wereweighed into a glass container having a clean lid and agitated by handuntil blended. Tap water was then weighed into a Waring blender jar. Thedry components were then mixed into the water with 4,000 rpm stirring.The blender speed was then increased to 12,000 rpm for about 35 seconds.

Sample Fluid No. 8 was an 11 pound per gallon slurry that comprised60.79% water, 30.42% cement kiln dust, 4.13% fly ash, 0.17% free watercontrol additive (WG-17™ solid additive), 3.45% bentonite, and 1.04%Econolite™ additive.

The oil-based drilling fluid was a 9.1 pound per gallon oil-based mud.

Rheological values were then determined using a Fann Model 35Viscometer. Dial readings were recorded at speeds of 3, 6, 100, 200, and300 with a B1 bob, an R1 rotor, and a 1.0 spring. The dial readings,plastic viscosity, and yield points for the spacer fluid and drillingfluid were measured in accordance with API Recommended Practices 10B,Bingham plastic model and are set forth in the table below. Theabbreviation “PV” refers to plastic viscosity, while the abbreviation“YP” refers to yield point. The abbreviation “OBM” refers to oil-basedmud.

TABLE 3 YP (lb/ Sample Temp. Viscometer RPM PV 100 Fluid (° F.) 300 200100 6 3 (cP) ft²) 8 80 59 50 39 22 15 42 21.2 180 82 54 48 16 13 65.3 17OBM 80 83 64 41 11 10 74.6 12.1 180 46 35 23 10 10 36.7 10.5

Accordingly, the above example illustrates that the addition of cementkiln dust to a treatment fluid may provide suitable properties for usein subterranean applications. In particular, the above exampleillustrates, inter alia, that the cement kiln dust may be used toprovide a treatment fluid with a yield point that is greater than adrilling fluid even at elevated temperatures. For example, Sample FluidNo. 8 has a higher yield point at 180° F. than the oil-based mud.

Example 4

A foamed treatment fluid (Sample Fluid 9) was prepared that comprisedcement kiln dust. First, a base slurry was prepared that had a densityof 10 ppg and comprised cement kiln dust, a free water control additive(0.7% by weight of cement kiln dust), a lightweight additive (4% byweight of cement kiln dust), and fresh water (32.16 gallons per 94-poundsack of cement kiln dust). The free water control additive was SA-1015™suspending aid. The lightweight additive was ECONOLITE™ additive. Next,a foaming agent (FOAMER™ 760 foamer/stabilizer) in an amount of 2% bvowwas added, and the base slurry was then mixed in a foam blending jar for4 seconds at 12,000 rpm. The resulting foamed treatment fluid had adensity of 8.4 ppg. The “sink” of the resultant foamed treatment fluidwas then measured using a free fluid test procedure as specified in APIRecommended Practice 10B. However, rather than measuring the free fluid,the amount of “sink” was measured after the foamed treatment fluidremained static for a period of 2 hours. The foamed treatment fluid wasinitially at 200° and cooled to ambient temperature over the 2-hourperiod. The measured sink for this foamed treatment fluid was 5millimeters.

Example 5

Another foamed treatment fluid (Sample Fluid 10) was prepared thatcomprised cement kiln dust. First, a base slurry was prepared that had adensity of 10.5 ppg and comprised cement kiln dust, a free water controladditive (0.6% by weight of cement kiln dust), a lightweight additive(4% by weight of cement kiln dust), and fresh water (23.7 gallons per94-pound sack of cement kiln dust). The free water control additive wasSA-1015™ suspending aid. The lightweight additive was ECONOLITE™additive. Next, a foaming agent (a hexylene glycol/cocobetaine blendedsurfactant) in an amount of 2% bvow was added, and the base slurry wasthen mixed in a foam blending jar for 6 seconds at 12,000 rpm. Theresulting foamed treatment fluid had a density of 8.304 ppg. Theresultant foamed treatment fluid had a sink of 0 millimeters, measuredas described above for Example 4.

Example 6

The following series of tests were performed to determine thecompressive strength of sample treatment fluids after consolidation.Twenty-two samples, labeled sample fluids 11-32 in the table below, wereprepared having a density of 12.5 ppg using various concentrations ofadditives. The amount of these additives in each sample fluid areindicated in the table below with “% by weight” indicating the amount ofthe particular component by weight of Additive 1+Additive 2. Theabbreviation “gal/sk” in the table below indicates gallons of theparticular component per 94-pound sack of Additive 1 and Additive 2.

The cement kiln dust used was supplied by Holcim (US) Inc., from Ada,Okla. The shale used was supplied by Texas Industries, Inc., fromMidlothian, Tex. The pumice used was either DS-200 or DS-300 lightweightaggregate available from Hess Pumice Products, Inc. The silica flourused was SSA-1™ cement additive, from Halliburton Energy Services, Inc.The course silica flour used was SSA-2™ course silica flour, fromHalliburton Energy Services, Inc. The metakaolin used was MetaMax®metakaolin, from BASF. The amorphous silica used was SILICALITE™ cementadditive, from Halliburton Energy Services, Inc. The perlite used wassupplied by Hess Pumice Products, Inc. The slag used was supplied byLaFarge North America. The Portland cement Interground with pumice wasFineCem™ cement, from Halliburton Energy Services, Inc. The fly ash usedwas POZMIX® cement additive, from Halliburton Energy Services, Inc. Themicro-fine cement used was MICRO MATRIX® cement having an averageparticle size of 7.5 microns, from Halliburton Energy Services, Inc. Therice husk ash used was supplied by Rice Hull Specialty Products,Stuttgart, Ark. The biopolymer used was supplied by CP Kelco, San Diego,Calif. The barite used was supplied by Baroid Industrial DrillingProducts. The latex used was Latex 3000™ cement additive fromHalliburton Energy Services, Inc. The ground rubber used was LIFECEM™100 cement additive from Halliburton Energy Services, Inc. The nano-clayused was supplied by Nanocor Inc. The set retarder used was SCR-100™cement retarder, from Halliburton Energy Services, Inc. SCR-100™ cementretarder is a copolymer of acrylic acid and 2-acrylamido-2-methylpropanesulfonic acid.

After preparation, the sample fluids were allowed to cure for seven daysin a 2″ by 4″ metal cylinder that was placed in a water bath at 180° F.to form set cylinders. Immediately after removal from the water bath,destructive compressive strengths were determined using a mechanicalpress in accordance with API RP 10B-2. The results of these tests areset forth below. The term “cement kiln dust” is abbreviated “CKD” in thetable below.

TABLE 4 Additive #1 Additive #2 Additive #3 Cement 7-Day Sam- % % % SetComp. ple Water by by by Retarder Strength Fluid gal/sk Type wt Type wtType wt % by wt PSI 11 5.72 CKD 50 Shale 50 — — 0 510 12 4.91 Pumice 50Lime 50 — — 1 646 DS- 200 13 5.88 CKD 50 Silica Flour 50 — — 0 288 146.05 CKD 50 Metakaolin 50 — — 0 104 15 5.71 CKD 50 Amorphous 50 — — 1251 Silica 16 5.13 CKD 50 Perlite 50 — — 0 1031 17 5.4 CKD 50 Lime 50 —— 0 58 18 5.49 CKD 50 Pumice DS- 50 — — 0 624 200 19 6.23 CKD 50 Slag 50— — 0 587 20 5.88 CKD 50 Course 50 — — 0 1018 Silica Flour 21 6.04 CKD50 Portland 50 — — 1 1655 Cement Interground with Pumice 22 5.63 CKD 50Fly Ash 50 — — 0 870 23 5.49 CKD 50 Pumice DS- 50 — — 0 680 325 24 5.03Fly 50 Lime 50 — — 170 Ash 25 5.65 Slag 50 Lime 50 — — 1 395 26 6.36 CKD50 Micro-fine 50 — — 2 788 cement 27 6.08 CKD 80 Rice Husk 20 — — 1 203Ash 28 5.42 CKD 50 Biopolymer 50 — — 1 265 29 7.34 CKD 50 Barite 50 — —0 21 30 4.02 CKD 100 — — Latex 2 1 164.6 31 2.71 CKD 100 — — Ground 10 1167.6 Rubber 32 6.15 CKD 100 — — Nano- 2 0 102.5 Clay

Accordingly, the above example illustrates that a treatment fluidcomprising kiln dust may be capable of consolidation. For example, 7-daycompressive strengths of 1000 psi or even higher were observed forcertain sample slurries.

Example 7

The following series of tests were performed to evaluate the thickeningtimes of sample treatment fluids. For this example, the thickening timesfor Sample Fluids 11-32 from Example 6 were determined. As indicatedbelow, the compositions for Samples Fluids 11-32 were the same as fromExample 6 except the concentration of the cement set retarder wasadjusted for certain samples. The thickening time, which is the timerequired for the compositions to reach 70 Bearden units of consistency,was determined for each fluid at 230° F. in accordance with API RP10B-2. The results of these tests are set forth below. The term “cementkiln dust” is abbreviated “CKD” in the table below.

TABLE 5 Additive #1 Additive #2 Additive #3 Cement % % % Set ThickeningSample Water by by by Retarder Time Fluid gal/sk Type wt Type wt Type Wt% by wt hr:min 11 5.72 CKD 50 Shale 50 — — 1 11:04  12 4.91 Pumice 50Lime 50 — — 1 0:30 DS- 200 13 5.88 CKD 50 Silica Flour 50 — — 1 3:31 146.05 CKD 50 Metakaolin 50 — — 1 3:13 15 5.71 CKD 50 Amorphous 50 — — 12:15 Silica 16 5.13 CKD 50 Perlite 50 — — 1 7:30 17 5.4 CKD 50 Lime 50 —— 1 2:42 18 5.49 CKD 50 PumiceDS- 50 — — 1 10:00  200 19 6.23 CKD 50Slag 50 — — 1 8:08 20 5.88 CKD 50 Course 50 — — 1 20 hr+ Silica Flour 216.04 CKD 50 Portland 50 — — 1 5:58 Cement Interground with Pumice 225.63 CKD 50 Fly Ash 50 — — 1 12 hr+ 23 5.49 CKD 50 Pumice DS- 50 — — 17:30 325 24 5.03 Fly 50 Lime 50 — — 1 3:32 Ash 25 5.65 Slag 50 Lime 50 —— 1 4:05 26 6.36 CKD 50 Micro-fine 50 — — 2 1:30 cement 27 6.08 CKD 80Rice Husk 20 — — 1 30 hr+ Ash 28 5.42 CKD 50 Biopolymer 50 — — 1 1:35 297.34 CKD 50 Barite 50 — — 1 18 hr+ 30 4.02 CKD 100 — — Latex 2 1 1:10 312.71 CKD 100 — — Ground 10 1 20 hr+ Rubber 32 6.15 CKD 100 — — Nano- 2 054:00  Clay

Accordingly, the above example illustrates that a settable spacer fluidmay have acceptable thickening times for certain applications.

Example 8

The following series of tests were performed to evaluate the rheologicalproperties of sample fluids. For this example, the rheologicalproperties of Sample Fluids 11-32 were determined. The rheologicalvalues were determined using a Fann Model 35 Viscometer. Dial readingswere recorded at speeds of 3, 6, 30, 60, 100, 200, 300, and 600 with aB1 bob, an R1 rotor, and a 1.0 spring. An additional sample was used forthis specific test. It is Sample Fluid 33 and comprised barite and 0.5%of a suspending agent by weight of the barite. The suspending agent wasSA™-1015, available from Halliburton Energy Services, Inc. The water wasincluded in an amount sufficient to provide a density of 12.5 ppg.Sample 33's rheological properties were measured twice at two differenttemperatures and the values per temperature were averaged to present thedata shown below. Temperature is measured in degrees Fahrenheit. Theresults of these tests are set forth below.

TABLE 6 Additive Additive Sample #1 % by Additive #2 % by #3 % byViscometer RPM Fluid Type wt Type wt Type wt Temp. 300 200 100 60 30 6 3600 11 CKD 50 Shale 50 — — 80 29 21 14 11 9 6 5 39 12 Pumice 50 Lime 50— — 80 24 17 9 6 5 2 1 48 DS-200 13 CKD 50 Silica Flour 50 — — 80 16 128 6 5 4 3 24 14 CKD 50 Metakaolin 50 — — 80 36 28 19 15 12 9 8 64 15 CKD50 Amorphous 50 — — 80 31 24 18 14 12 10 9 49 Silica 16 CKD 50 Perlite50 — — 80 40 34 27 23 20 15 9 61 17 CKD 50 Lime 50 — — 80 46 41 34 30 2716 11 65 18 CKD 50 Pumice DS- 50 — — 80 23 19 14 11 9 7 6 40 200 19 CKD50 Slag 50 — — 80 23 20 14 11 9 6 5 41 20 CKD 50 Course 50 — — 80 27 1912 9 7 4 3 64 Silica Flour 21 CKD 50 Portland 50 — — 80 15 10 7 5 3 2 118 Cement Interground with Pumice 22 CKD 50 Fly Ash 50 — — 80 12 9 6 4 32 1 21 23 CKD 50 Pumice DS- 50 — — 80 39 32 24 21 17 12 7 57 325 24 FlyAsh 50 Lime 50 — — 80 12 9 6 4 3 2 2 24 25 Slag 50 Lime 50 — — 80 15 105 3 2 1 1 23 26 CKD 50 Micro-fine 50 — — 80 10 7 4 3 2 1 0 14 cement 27CKD 80 Rice Husk 20 — — 80 24 15 9 7 5 3 2 41 Ash 28 CKD 50 Biopolymer50 — — 80 175 111 53 31 15 4 3 220 29 CKD 50 Barite 50 — — 80 48 40 3026 22 15 13 2 30 CKD 100 — — Latex 2 80 48 39 28 23 19 17 15 82 31 CKD100 — — Ground 10 80 65 56 42 40 39 30 22 105 Rubber 32 CKD 100 — —Nano- 2 80 22 18 12 10 8 6 5 37 Clay 33 Barite 100 — — SA™- 0.5 80 4136.5 30.5 28 25.5 20.5 18.5 NA 1015 33 Barite 100 — — SA™- 0.5 180 3835.5 32 30 28 23.5 22 NA 1015

Accordingly, the above example indicates that a treatment fluid may haveacceptable rheological properties for a particular application.

Example 9

The following series of tests were performed to further evaluate thecompressive strength of sample treatment fluids. Ten samples, labeledSample Fluids 34-43 in the table below were prepared, having a densityof 13 ppg using various concentrations of additives. The amount of theseadditives in each sample are indicated in the table below with “% byweight” indicating the amount of the particular component by weight ofthe dry solids, which is the kiln dust, the Portland cement, the cementaccelerator, the fly ash, and/or the lime. The abbreviation “gal/sk” inthe table below indicates gallons of the particular component per94-pound sack of the dry solids. The term “cement kiln dust” isabbreviated “CKD” in the table below.

The cement kiln dust used was Mountain cement kiln dust from LaramieWyo., except for Sample Fluid 43 which used cement kiln dust from Holcim(US) Inc., Ada, Okla. The Portland cement used in Sample Fluids 34 and35 was CEMEX Type 3 Portland cement, from CEMEX USA. The cementaccelerator used in Sample Fluid 34 was CAL-SEAL™ accelerator, fromHalliburton Energy Services Inc. CAL-SEAL™ Accelerator is gypsum. TheClass F fly ash used in Slurries 37-41 was from Coal Creek Station. TheClass C fly ash used in Slurries 36 was from LaFarge North America.

After preparation, the samples were allowed to cure for twenty-four orforty-eight hours in a 2″ by 4″ metal cylinder that was placed in awater bath at 160° F. to form set cylinders. For certain samples,separate cylinders were cured for twenty-four hours and forty-eighthours. Immediately after removal from the water bath, destructivecompressive strengths were determined using a mechanical press inaccordance with API RP 10B-2. The results of these tests are set forthbelow.

TABLE 7 Class Class Portland Cement F Fly C Fly 24-Hr 48-Hr CementAccel. Ash Ash Lime Comp. Comp. Sample Water CKD % % by % by % by % by %by Strength Strength Fluid gal/sk by wt wt wt wt wt wt PSI PSI 34 8.7585 10 5 0 0 0 73.4 — 35 8.75 90 10 0 0 0 0 99.8 — 36 8.14 70 0 0 0 30 0210 — 37 8.25 70 0 0 25 0 5 388 — 38 8.20 75 0 0 21 0 4 300 784 39 8.2780 0 0 17.5 0 2.5 224 641 40 9.61 70 0 0 25 0 5 219 567 41 11.5 70 0 025 0 5 165 369 42 5.12 100 0 0 0 0 0 36.2 — 43 5.12 100 0 0 0 0 0 60.8 —

Accordingly, the above example illustrates that a treatment fluid mayhave acceptable compressive strengths for certain applications.

Example 10

The following series of tests were performed to evaluate the static gelstrength development of sample treatment fluids. Two samples, labeledSample Fluids 44 and 45 were prepared having a density of 11 and 13.5ppg respectively using various concentrations of additives. Thecomponent concentrations of each sample are as follows:

For Sample Fluid 44, the sample comprised a blend of cement kiln dust(80% by weight), fly ash (16% by weight) and hydrated lime (4% byweight). The sample also comprised a suspending aid in an amount of 0.4%by weight of the blend. Sufficient water was included in the sample toprovide a density of 11 ppg. The cement kiln dust used was from Holcim(US) Inc., Ada, Okla. The fly ash used was POZMIX® cement additive, fromHalliburton Energy Services, Inc. The suspending agent was SA™-1015suspending agent, available from Halliburton Energy Services, Inc.

For Sample Fluid 45, the sample comprised a mixture of cement kiln dust(80% by weight), fly ash (16% by weight), and hydrate lime (4% byweight). Sufficient water was included in the sample to provide adensity of 13.5 ppg. The cement kiln dust used was from Holcim (US)Inc., Ada, Okla. The fly ash used was POZMIX® cement additive, fromHalliburton Energy Services, Inc.

The static gel strength of the samples was measured in accordance withAPI Recommended Practice on Determining the Static Gel Strength ofCement Formations, ANSI/API Recommended Practice 10B-6. FIGS. 1 and 2show the static gel strength measurements for Sample Fluids 44 and 45,respectively, as a function of time. As seen in the figures, the samplesprogress through the transition time, defined as the time between 100SGS and 500 SGS, very quickly with a total transition time of 19 minutesfor the sample 34 and 6 minutes for sample 35. These short transitiontimes are faster than most cement compositions.

Example 11

The following tests were performed to further evaluate the static gelstrength development of sample treatment fluids. Two samples, labeledSamples Fluids 46 and 47 were prepared having a density of 13.002 and10.999 ppg respectively using various concentrations of additives. Thecomponent concentrations of each sample are as follows:

For Sample Fluid 46, the sample comprised a blend of cement kiln dust(100% by weight), POZMIX® cement additive (50% by weight of the cementkiln dust), He-601 cement retarder (1% by weight of the cement kilndust), HR®-25 cement retarder (0.6% by weight of the cement kiln dust),and D-Air 5000™ defoamer (0.5% by weight of the cement kiln dust).Sufficient water was included in the sample to provide a density of13.002 ppg. The cement kiln dust used was from Holcim (US) Inc., Ada,Okla. POZMIX® cement additive was from Halliburton Energy Services, Inc.HR®-601 cement retarder was from Halliburton Energy Services, Inc.HR®-25 cement retarder was from Halliburton Energy Services, Inc. D-Air5000™ defoamer was from Halliburton Energy Services, Inc.

For Sample Fluid 47, the sample comprised a blend of cement kiln dust(100% by weight), SA-1015 (0.4% by weight of the cement kiln dust), andD-Air 5000™ defoamer (0.5% by weight of the cement kiln dust).Sufficient water was included in the sample to provide a density of10.999 ppg. The cement kiln dust used was from Holcim (US) Inc., Ada,Okla. SA™-1015 suspending agent was from Halliburton Energy Services,Inc. D-Air 5000™ defoamer was from Halliburton Energy Services, Inc.

The static gel strength of the samples was measured in accordance withAPI Recommended Practice on Determining the Static Gel Strength ofCement Formations, ANSI/API Recommended Practice 10B-6. Table 8 showsthe static gel strength measurements for Samples Fluids 46 and 47,respectively.

TABLE 8 Difference between 100 Time to reach Time to reach lbf/100ft^(s) and Sample Temp 100 lbf/100 ft^(s) 500 lbf/100 ft^(s) 500 lbf/100ft^(s) Fluid (° F.) (hr:min) (hr:min) (hr:min) 46 220 3:25 5:04  1:39 47220 3:07 3:17 00:10As seen in the table, Sample Fluid 47 progresses through the transitiontime, defined as the time between 100 SGS and 500 SGS, very quickly witha total transition time of 10 minutes. Sample Fluid 46 is much slowertaking over an hour to progress through the transition time. The shorttransition time of Sample Fluid 47 is faster than most cementcompositions.

It should be understood that the compositions and methods are describedin terms of “comprising,” “containing,” or “including” variouscomponents or steps, the compositions and methods can also “consistessentially of” or “consist of” the various components and steps.Moreover, the indefinite articles “a” or “an,” as used in the claims,are defined herein to mean one or more than one of the element that itintroduces.

For the sake of brevity, only certain ranges are explicitly disclosedherein. However, ranges from any lower limit may be combined with anyupper limit to recite a range not explicitly recited, as well as, rangesfrom any lower limit may be combined with any other lower limit torecite a range not explicitly recited, in the same way, ranges from anyupper limit may be combined with any other upper limit to recite a rangenot explicitly recited. Additionally, whenever a numerical range with alower limit and an upper limit is disclosed, any number and any includedrange falling within the range are specifically disclosed. Inparticular, every range of values (of the form, “from about a to aboutb,” or, equivalently, “from approximately a to b,” or, equivalently,“from approximately a-b”) disclosed herein is to be understood to setforth every number and range encompassed within the broader range ofvalues even if not explicitly recited. Thus, every point or individualvalue may serve as its own lower or upper limit combined with any otherpoint or individual value or any other lower or upper limit, to recite arange not explicitly recited.

Therefore, the present invention is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent invention may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Although individual embodiments arediscussed, the invention covers all combinations of all thoseembodiments. Furthermore, no limitations are intended to the details ofconstruction or design herein shown, other than as described in theclaims below. Also, the terms in the claims have their plain, ordinarymeaning unless otherwise explicitly and clearly defined by the patentee.It is therefore evident that the particular illustrative embodimentsdisclosed above may be altered or modified and all such variations areconsidered within the scope and spirit of the present invention. Ifthere is any conflict in the usages of a word or term in thisspecification and one or more patent(s) or other documents that may beincorporated herein by reference, the definitions that are consistentwith this specification should be adopted.

What is claimed is:
 1. A drilling system comprising: a bottom holeassembly comprising a drill bit; a cement composition; a drilling fluid;and a consolidating spacer fluid for introduction into a wellborethrough the drill bit between the drilling fluid and the cementcomposition, wherein the consolidating spacer fluid comprises a kilndust and water.
 2. The system of claim 1, further comprising a tubular,wherein the bottom hole assembly is attached to the tubular.
 3. Thesystem of claim 2, wherein the tubular is a drill pipe, a casing, or acombination thereof.
 4. The system of claim 1, wherein the bottom holeassembly is retrievable.
 5. The system of claim 1, wherein the bottomhole assembly is non-retrievable.
 6. The system of claim 1, wherein atleast a portion of the wellbore extends at a direction that is slantedfrom vertical.
 7. The system of claim 1, wherein the consolidating fluidhas a transition time of about 45 minutes or less.
 8. The system ofclaim 1, wherein the consolidating spacer fluid has a density of about 4pounds per gallon to about 13 pounds per gallon.
 9. The system of claim1, wherein the kiln dust is from the manufacture of cement.
 10. Thesystem of claim 1, wherein the kiln dust comprises SiO₂, Al₂O₃, Fe₂O₃,CaO, MgO, SO₃, Na₂O, and K₂O.
 11. The system of claim 1, wherein thekiln dust may be present in the consolidating spacer fluid in an amountof about 1% to about 65% by weight of the consolidating spacer fluid.12. The system of claim 1 wherein the consolidating spacer fluid iscapable of displacing at least a portion of the drilling fluid from thewellbore.
 13. A drilling system comprising: a bottom hole assemblycomprising a drill bit; a drilling fluid; a cement composition; and aconsolidated spacer fluid for introduction into a wellbore through thedrill bit between the drilling fluid and the cement composition, whereinthe consolidated spacer fluid comprises a kiln dust and water, whereinthe consolidated spacer fluid has at least one property selected fromthe group consisting of: (i) a yield point of from about 25 Pascals toabout 250 pascals; (ii) a static gel strength of from about 70 lbf/100ft² to about 500 lbf/100 ft², (iii) a yield limit in compression fromabout 1 psi to about 2,000 psi, and (iv) an unconfined uniaxialcompressive strength of from about 5 psi to about 10,000 psi.
 14. Thesystem of claim 13, wherein the consolidated spacer fluid further has atleast one property selected from the group consisting of: (i) a zero geltime of about 8 hours or less, (ii) a transition time of about 45minutes or less, and (iii) a static gel strength of about 500 lbf/100ft² in a time of from about 10 minutes to about 8 hours.
 15. The systemof claim 13, wherein the kiln dust is from the manufacture of cement.16. The system of claim 13, further comprising a bond log capable formeasuring the degree of bonding of the consolidated spacer fluid to acasing in the well bore.